CA2198030A1

CA2198030A1 - Gas-lift system for removing liquid from gas wells

Info

Publication number: CA2198030A1
Application number: CA002198030A
Authority: CA
Inventors: Michael D. Hershberger
Original assignee: Individual
Current assignee: Individual
Priority date: 1994-08-19
Filing date: 1995-08-09
Publication date: 1996-02-29
Also published as: US5488993A; WO1996006263A1; AU3361795A

Abstract

An artificial lift system and method for lifting fluids from an underground formation. The artificial lift system comprising a production tubing (40) through which the fluid is carried from the formation to the surface and a pressure reducer (14), such as a venturi, fluidly connected to the production tubing to artificially raise the level of the fluid in the production tubing. The method comprises reducing the pressure in the production tubing at an upper portion thereof to increase the pressure differential between the uppper portion of the production tubing and a lower portion of the production tubing to increase the level of liquid in the production tubing for subsequent removal in an artificial lifting step.

Description

WO 96106263 P7~T/lJS95J~0056 GAS-LIFT SYSTEM FOR REMOVING LIQUID FROM GAS WELLS

BAC K G ROlJNlD OF I~DE IN~ENI~O N
Field of the Invention This invention relates to an ar ificial lift system for removing fluid ~ 5 from an ulld~ ullJ formation, and more specifica',ly to an - ~6 ~ a' d artificial lift system utilizing pressure reduction to mcrease the efflciency of the artificial lift system.
~crrintinn of Related Art Artificial lift systems are commonly used to extract fluids, such as 10 oiL water and natural gas, from ulld~.6 uulld geological ~ M.,..~ Often times, the ~.. 1 ;, . ~ are more than 1,000 feet below the surface of the earth.The intemal pressure of the geological fommation is of~en incl~ffi~i~onf to naturally raise collull~ quantities of the fluid or gas from the fommation through a bore hole. When the fomlation has a sufflcient internal pressure to 15 naturally lift the fluid from the fommation, the natural pressure is often i~q~ qt~ to produce the desired flow rate. Therefore, it is desirable to art,ficially lift the fluid from the fomnation by means of an ar,ificial lift system.
Typically, the fomlation can comprise several separate layers or strata containing the fluid or can comprise a sing',e large reservoir. A bore hole 20 is drilled into the earth and passes through the different layers of the fomlation until the deepest layer is reached. Due to economic .~ many bore holes extend on',y to the deepest part of the fomlation. In certain -l.l,l;. ~1;....~ it is desired to extend the bore hole beyond the bottom of the formation. The portion of the bore hole that extends beyond the bottom of the fomlation is 25 know l as a "rat hole.~ The location and depth of the bore hole is carefully controlled because of the great expense in drilling the bore hole.
After the bore hole is drilled, the bore hole is lined ,vith a casing ~ cnbstqntiqlly along its entire length to prevent collapse of the bore hole and to protect surface water from ~.. li... ' -l;.... However, the bore hole is often only 30 lined with the casing to the top of the gas and fluid containing fommation leaving the lower section of the bore hole uncased. The uncased section is referred to as an open hole. The casing is cemented in place and sealed at surface by a wellhead and can have one or more pipes, tubes or strirlgs (metal rods) disposed 3 2 1 9 3 !J 3 0 PCTIUS95110056 therein and extending into the bore hole from the wellhead. One of the tubes is typically a production tube, which is used to carry fluid to the surface.
Currently, many different types of artificial lift systems are used to lift the fluid from the formation. The most common artificial lift systems are:
5 ~IU~ iVG cavity pumps, beam pumps and 5 ~ r- ~ gas lift (SSGL). A
IJlU~jlC:l~iVc cavity pump is relatively expensive, d~lu~ $25,000, to install but can deliver relatively large volumes of fluid and remove all the fluid from the formation. A ~lu~ v~, cavity pump comprises an engine or electric motor driven hydraulic pump comnected to a hydraulic motor mounted on the top of 10 the wellhead and comnected to a hydraulic pump at the bottom of a IJlUdU~.IiUU
tubing. The hydraulic motor turns a rod string that is connected to a pump rotor, which turns with respect to a pump stator. The pump rotor is helical in shape and forms a series of IJIUE,. ~V.~ cavities as it turns to lift or pump the fluid from the bottom of the casing into the ~lud.,_Liun tube and to the surface.
15 Although the ~IU6.C.... V~ cavity pump is saL~L~luly in raising fluid from the formation, the hydraulic pump system requires a ~ building and liner in the event of an oil leak. The possibility of an oil leak in the ~.u6.~
cavity pump system also raises t,llVilUllll.~ ill concerns because many of the bore holes are drilled in ellvilu~ul~ lly sensitive or wilderness areas. The 20 IJIu~ . cavity pump also requires, in certain "~ , at least 100 feet ofa rat hole, which adds extra cost. Of the previously m~ntinn~d ar~ficial lift systems, the plU6.~ . cavity pump has the highest costs and greatest amount of down time requiring rig serv-ice. A soft seal stuffing box seals around the rotating rod string and must be lubricated daily and acoustic 25 annular fluid levels must be obtained at regular intervals to ensure that the fluid is adc~u~ high above the pump and that it does not run dry and destroy itself.
A beam pump is also relatively expensive, ~ lu~ dlcly $15,000, to install but can also remove all the fluid from the formation. The beam pump 30 comprises a pivotally mounted beam that is positioned over the wellhead and comnected to a rod string extending into the IJlUdU~.liUII tube in the bore hole.
The lower end of the rod string is connected to a pump disposed near the bottom of the bore hole. The beam pump is operated by a gas engine or an . . _ .
_ _ .. . . . . . ..

WO96106263 2 ~ 98 a ~ s/laos6 electric motor. If an electric rnotor is used, it is necessary to run power lines to the beam pump because many of the beam pumps are placed in remote ~ wilderness areas. The beam pump has several d;~ad~aulâ~_~. First, there are many _.IVilUILU~ concerns. There may be lealcage in the engine or gear box S of the power source, requiring ~;u~L~l inn of a ~ area Further, if an electric motor is used in place of the gas engine, it is necessary to run a power line to the electric motor, which often destroys or degrades the :~luullJiug l,.l~ilUI~ . The beam pump, like the ~IU~ _ cavity pump, has several .~ t' that require regular lllhrirzltfnn The beam pump also 10 uses a soft seal stuffing box to seal around the l~ lu~ali~ rod string.
The cl~hcllrfs~-~ ga lift (SSGL) is the least expensive artificial lift Svstem to install, a~!~lu~dt~ $7,500. The SSGL uses ~ u~d gas carried by a separate tube from the surface to the lower end of a ~,.. ' ~ tube to raise fluid in the 1~ ' tnbe upon injection of the ~ ui~d gas. The 15 ~ludu~,iiull tube usually has a one-way valve at its lower end so that fluid standing in the formation can enter the ~.u.lu.,liuu tube and rise in the ~-uJu~Liuu tube to the level of fluid in the formation. The SSGL can be used with or without a plunger disposed within the ~l~ ' tubing. The SSGL is the most e.~ , friendly and free of the three commonly 20 used artificial lift systems. UnlL~ce the other artificial lift systems, the ~llhc lrfq~e gas lift system requires no systematic l .h. :- ~ l of the gas regulator and themotor valve. The SSGL maintains greater integrity of the well head in cuuL-ulliug the possibility of fluid leaks because the well head '""'l""' '~ arehard piped with no friction oriented soft seal such as is found in the stuffing 25 boxes of the ~JIU~ ..;._ cavity and beam pumps. The SSGL is virtually silent during operation and has relatively little surface ~, . compared to a beam pump or ~,-u6, ,~ _ cavity pump. Therefore, it has less audible and visual impact on the ~UllUUu.li- g e..~;.ulllll-~ The greatest J~aJ~auL6~ of the SSGL
is that it becomes less efficient as more and more fluid is drawn from the 30 fnrmstinn The SSGL can only raise the column of fluid in the ~-udu.,liù..
tubing. The col= of fluid in the tubing is equal to the level of fluid in the formation. As more and more fluid is removed from the formation, the level of WO 96/06263 ~ 1 9 8 o 3 o r~l",~ 3~

fluid in the production tubing decreases and a ~ y smaller and smaller amount of fluid is raised for cllhct~nfi~lly the same amount of energy.
As the fluid level in the sllb~llrf~ gas lih system decreases, there becomes a point where it is no longer cost effective, orf r~tif~n~lly safe or 5 productive to use the subsurface gas lift system. Ohen times, the subsurface gas lih system is replaced with a beam pump, and its ~ J ~
attributes. Optionally, a "rat hole" can be bored with the bore hole in a subsurface gas lih system so that most of the fluid can be raised from the formation by placing the gas injection below the level of the formation and in 10 the rat hole. However, hundreds of bore holes were drilled without rat holes before artificial lift became a generally accepted method of lu~udu~ull and the cost associated with boring a rat hole is such that most companies still prefer to drill little, if any, rat holes.
Another J~aJv~lL6~ that is common to all artificial lift systems 15 in that as the fluid level decreases the system becomes u~ lly more difficult to efficiently control without damaging itseL~ In the event of no fluid level, the ~JIU~C .. ._ cavity will quickly torque up and seize the down hole pump or twist off the rod string. The beam pump will begin to pound as gas is drawn into the pump. The end result of whuch will be a scored pump barrel and 20 eventually a parted rod string. The SSGL may "dry cycle". A condition where the plunger arrives at the surface and bottom of the well with possible damagingvelocity. The damage to the ~,.u6.~ ....:.~ cavity and the beam pumps will require a work over rig for repairs. The damage to the SSGL seldom requires more than a small wire line truck for a few hours to retrieve and repair the 25 damaged cf~ 'I"' - t~ Each of these systems, if controlled hlllJIu~ ly~ can have ~,ah~ . ~ ~ failures that can be physically dangerous to the operator and can inflict e..~hu.llll..l~l damage.
Therefore, it is desirable to have a cost effective artificial lift system and process for a well that are relatively Cll~;lul.lll~ lly safe, low 30 ' ~ lly ~ J;~hblc, easy to control and which has an acceptable level of efficiency.

W096106263 219~3030 r~m..n,;

SUmmllrv of Inventlon According to the invention, I~-u~lu~,liuu of gas from a gas and Iiquid containing u~ d~,.~uuud strata from which a well extends from the surfaceof the ground tû the u~rd~ .uuud strata is enhanced by reducing the pressure at 5 an upper portion of a ~udu~iu~ tubmg to increase the pressure l;rf~..,.L,Il between an upper portion of the l~udu~Liu~l tubing and a lower portion of the production tubing which is fluidly connected with the u~ d~,.~uu~d strata The increase in the pressure lilf.,l~ al results in an increase in the volume of fluid in the ll-udù~iu~ tubing, which fluid is removed in an artificial lifting step. The 10 well has an outer casing through which the gas passes from the strata to the surface of the ground. The gas enters the lower portion of the outer casing which is disposed in the strata and moves through the outer casing to the surface of the ground where it is collected. The ylvdu~fiuu tubimg is disposed within the outer casing of the well. The liquid is removed from the well by artificially lifting the liquid from a lower portion of the well to the surface of the ground through the uludh~,Liu~ tubing. By removing the liquid from the well, gas is released from the formation and enters the annular section of the wcll bore to be produced from the formation. The pressure reducing step is used to aid in the removal of tbe liquid from the well.
The pressure reducing step is preferably carried out for a first time period to increase the volurnc of fluid which enters the ,ul. ' tubing.
Preferably, the artificial lifting step is carried out a ~ to the ~. . ' ~-of the fust time period. Alt~,.~li._l~, tbe lifting step can begin after the , '~ of the first time period. The artificial lifting step preferably comprises tbe injection of a bigh pressure gas for a second time period mto the lower portion of the production tubing to lift the liquid m the ,u~udu~tiu~ tubing.
Preferably, the pressure reducing step comprises tbe passing of a higb pressure gas through a reduced orifice to create a reduced pressure area adjacent the orifice. A portion of the liquid is drawn in bhe ~-udu~liu~ tubing and is passed30 into the reduced pressure area To this end, the orifice is fluidly connected to the ~ûdu~iu~ tubing so that the reduced pressure area is fluidly connected to the l~udu~fiu~ tubmg area In the lifting step, the fluid drawn into tbe production tubing is lifted by the injection of bigh pressure gas into ube lower .:

WO 96/06263 PCT/US95/100~6 2~ 98030--portion of the production tubing. In a collection step, the liquid lifted from the production tubing and the gas exiting the annulus are preferably directed to a common tubing where the gas and liquid are mixed and carried to a collecting zone and sllhs~qll~ntly separated.
In another . .ho~ l of the invention, a gas ~ludu~lioll well extends between the surface of the ground to the strata, which contains gas and liquid. The well has an outer casing with a fluidly open lower portion through which the gas passes from the strata and wherein the upper portion of the outer casing is connected to a gas collector at the surface of the groumd so that the 10 gas passes from the lower portion of the outer casing to the collector through the outer casmg. The well further has an ilmer J~luJu~liuu tubing disposed within the outer casing and by which the liquid is removed from the well with anartificial lift system. The artificial lift system lifts the liquid frorn the lower portion of the well to the ground level to release gas from the forrnation into the annulus. A pressure reducer is fluidly conmected to an upper portion of the UlUdU~IiOll tubing to increase the pressure ~lifr~.c.l~l at the surface between thc luludu~liull tubing and the annular section of the well bore to thereby increase the rate of fluid entry and the level of liquid in the production tubing for removal by the artificial lift system.
The pressure reducer is preferably a venturi that is fluidly connected to a source of pl~ d gas sû that when the Ul~ ' ~ gas passes through the venturi a reduced pressure area is formed by the venturi, thereby raising the level of liquid in the ~ll ' tubmg above the level of liquid in the outer casing. The venturi has a tubular body with an axial opening extending ~LC~lIIIUU~SII from a first end to a second end and in which is l~pldccalJl~ mounted a nozzle and an induction barrel. The nozzle is retained within the main body by a nozzle retainer threadably mounted to the axial aperture at the first end of the tubular body. The induction barrel is retaincd within the main body by a barrel retainer lluc~ mounted to the axial 30 aperture at the second end of the tubular body so that the nozzle retainer and barrel retainer, ICi~ , provide access to the nozzle and the induction barrel. The tubular body preferably has an annular shoulder extending into the axial aperture and against which the nozzle and the induction barrel abut so ~: ~ _ _ . _ _ _ _ , . . .. . . . . . . . ....

WO 96106263 PCT/17S9~i~100~6 ~ -7- 21 9803~

that the nozzle and the induction barrel can be ~.U1U~ICDD;~ mounted betveen the annular shoulder and the nozle retainer and barrel retainer, respectively.
The spacers can be disposed between either side of the amlular shoulder and the nozzle and induction barrel, I~D~C~L~ to adjust the position of the nozle 5 and induction barrel within the main body.
In yet another ~ ,l-o~ of the invention, the gas l,.udu~Liu..
well comprises a ~.udu~.liu.. Iine extending from the outer cacing for removal of the gas in the annulus outer casing and the pressure reducer fluidly connected to the production tubing. Also, the gas production well comprises an induction 10 line extending from the ~JIUIh. iiUII tubing to the pressure reducer for fluidly C~ g the pressure reducer to the IJludu-;Liull tubing.
The invention provides a gas or oil well artificial lift system and process which are relatively e....-u~,.-L~lly safe, cost effective and efficient.
Brief Descrintion of the Drawinec The invention will now be described with reference to the drawings in which:
FIG. 1 is a sectional view of a bore hole with an artificial lift system according to the invention;
FIG. 2 is an enlarged sectional view of the induction system for 20 the artificial lift system of FIG. 1;
F~G. 3 is a schematic view of a second ~ ' - ' well assembly for the artificial lift system according to the invention;
FIG. 4 is a schematic view of a third ~ I~ud;~ -- 1 well assembly for the artificial lift system according to the invention;
FIG. 5 is a schematic view of a second P l.u l:- ' of the artificial lift system according to the invention; and FIG. 6 is a schematic view of a third c hod~ of the artificial lift system according to the invention.
D. ~ ' of the Prcferred r FIG. 1 illustrates the artificial lift system 10 according to the invention and comprises a subsurface gas lift system 12 (SSGL) in .. 1~
with an induction system 14. The SSGL 12 and induction system 14 are closed to the ~hlloDyL~ creating a closed artificial Lft system.

.

WO g6/06263 . ~,l/U.,,~
-8- 2 ~ 9~3~ --The SSGL 12 comprises well assembly 16 extending from above a surface 24, such as the ground, and into an underground formation 28 and tû
which is fluidly connected a high pressure gas source 18 and a collector 20 for collecting and separating the fluids.
As illllctr~t~A the formation contains two types of fluid, natural gas 30 and water 32 in the liquid state. However, other types of fluid such as liquid L,J.u~bu~s can be in the formation 28. Also, the formation is illustrated as having a cavern. However, it is possible that the formation does not have a cavern, but comprises multiple layers or strata. The artificial lift system 10 will work in either formation c~ r;6,~
The fluid in the formation is generaLy under pressure as a result of the weight of the formation bearing on the fluid and the pressure associated with the fluids ih_~ .. The internal pressure of the formation is known as the head pressure and generally varies as a fimction of the distance a particular 15 portion of the formation is from the surface. For example, the greater tbe depth of thc formation, the greater the head pressure is of that portion of the formation. Cu--~ l, ,J~, all areas of a given depth, that have not been depleted of their fluids, generally have the same head pressure.
The fluid in the formation is generally separated by its different 20 densities such that typically the water is positioned below the natural gas.
Although some of the natural gas is free to move within the formation, much of the natural gas is trapped in the material ~ the formation because of the head pressure of the formation and no available room for expansion. The trapped natural gas cannot be removed from the formation, unless the natural gas is free to escape the formation. To free the natural gas from the formation,the water in the formation is typically removed therefrom to reduce the head pressure and to provide a volume into which the natural gas is free to expand.
Once free of the formation, the natural gas can migrate or be drawn to the well a sembly 16 for removal.
The well a sembly 16 comprises a casing 22 disposed from the surface 24 and extending into the bore hole 26 and into the fortnation 28.
Preferably, the casing 22 extends s-lhctqntiqlly to the bottorn of the formation 28 and is open at the lower end or has any suitable p ~ through which the .. .. ... ~

WO 961067.63 PCT/US95S~00~;6 fluids can pass. However, other well slcc~mhlif c are possible. Two alternative well ...hl f c are illustrated in FIGS 3 and 4.
- The casing 22 is sealed with respect to the a--- q~ c at its upper end by a wellhead 36. A IUlUdU~LiUu tubing 40 extends through the wellhead 36 and t~.u~s cllhct~ntislly near the bottom of the bore hole 26. Although the casing ~ is illustrated as extending the entire length of the bore hole, the casing ~ may or may not extend to the bottom of the bore hole, depending on the ;..., However, the casing ~ is present at the surface of the bore hole and ~ u~,l, .. I . c with the wellhead 36 to seal the bore hole 26 with respect to the 10 a~u~U~ . c.
An annulus 38 is formed by the inner diameter of the casing and the outer diameter of the ~ ' tubing. The lower end of the ~JIUdU~LiUII
tubing 40 has an injection mandrel 42 in which is mounted a one-way standing valve 44. A high pressure tubing 46 extends from the high pressure gas source 15 18, through the wellhead 36 and to the injection mandrel 42. Preferably, the high pressure tubing 46 connects with the injection mandrel 42 above the standing valve 44. When high pressure gas is directed from the high pressure gas source 18 into the ~-uJu~iu~ tubing 40 through the high pressure gas tubing 46, the standing valve 44 prohibits the high pressure gas from escaping from the20 I ~udu~iùu tubing 40 and keeps the high pressure gas out of the aDnulus 38. Aplunger 48 can be disposed in the l~u~l l;.. tubing 40 abûve the inlet for the high pressure tubing 46 and is sized to fit within close tolerance of the inner diameter of the yludu.liuu tubing 40. An open hole (uncased) section or a series of p.. r... ,. I ;.. ~ 23 are formed in the casing so that the fluids, such as the 25 natural gas and water, can enter the annulus 38.
The casing ~ also has a ~ludu~Liuu line 25 positioned at the surface 24 and extending to the collector 20 so that the natural gas entering the annulus 38 through the p.,.rulf~Liul~ 23 or open hole can be directed to the collector 20. A valve 27 and a check valve 29 are disposed within the 30 l~udu~ line 25 between the casing ~ and the collector 20. The valve 27 and the check valve 29 control the flow of fluid from the annulus 38 to the collector 20. Preferably the valve 27 is a manually operated valve to close the production line 25, whereas the check valve 29 is a one-way valve that pelmits alq~3~
WO 96/06263 PCTNS95/100!i6 -10- 2 1 9 ~ 3 ~

the flow of the fluid from the annulus 38 to the collector 20 but prohibits flowfrom the collector into the annulus.
A motor valve 56 and a valve 58 are fluidly connected to the high pressure gas source 18. A high pressure fluid line 46 extends from the motor S valve 56 to the injection mandrel 42 of the ~ludu~Lu~ tubing 40. Preferably, the motor valve 56 and the valve 58 are disposed above the surface 24. The valve 58 is preferably a manually operated valve for opening and closing the high pressure tubing 46 when desired. The motor valve 56 is connected to a contrQller 60 having a timer. The controller 60 can be ,ulu2; ..~ lr and opens 10 and closes the motor valve 56 sû that the high pressure gas from the high pressure gas source 18 can be injected into the production tubing 40 at u.~d~ . . ".;. rd intervals. The controller may be connected to a pressure LlCLlLtdU~.. 170 positioned on the ~lo-lu.Lu.. tubing 40 or on the annulus 38.
The pressure llo~t-lu~. 170 senses the gas pressure at the top of the l,lu-lu.Lo.
15 tubing 40 or may sense a pressure diL'f~ .~ .L~I between the yludu~Loll tubing 40 and the annulus 38.
A lubricator 66 is mounted to the wellhead 36 above the l.lu.lu.Lull tubing 40 and is fluidly connected to the ~ ludu~Lùn tubing 40. Thelubricator 66 is an extension of the l,lu-lu.Lull tubing 40. The lubricator 20 preferably has a biasing device, such as a spring 68, positioned at the upper end of the lubricator 66 when a plunger 48 is disposed in the ~ ' tubing 40.
The spring 68 functions to stop the upper IllU. of the plunger 4g. The lubricator 66 can consist of any device with an outlet to the injection line 74 if a plunger 48 is not disposed in the ~I. h tubing 40. A valve 70 is disposed 25 at the top of the ,ulu-lu~Lull tubing 40 and is preferably manually operated to open and close the flow of fluid through the l,mùdu.Lull tubing 40 and lubricator 66 when desired.
An injection line 74 extends from the lubricator 66, preferably above the valve 70, and connects with the ~ludu~Liun line 25 via the 3û ~ r line 76. A valve 80 and a check valve 82 arc disposed within the injection line 74. The valve 80 is a manually operated valve to open and close the injection line 74, whereas the check valve 82 is preferably a one-way valve for permitting the flow of fluid from the lubricator 66 to the production line 25, _ . . .... . . . ... . .... . ... . .. .. _ _ . . . . _ . .. . . . _ _ .

WO 96106263 PCTIUS95~10056 -11- 2~ ~3030 but ,u~ Lu~, the flow of fluid from the production line 25 to the injection line 74. The check valves 29 and 82 keep fluid from back flowing from the ..Kl;,~e line 76 into the l~uJu~,Lu~ tubing 40 or the casing 22.
The check vahes 29 and 82 fluidly isolate the annulus 38 and the 5 production tubing 40 from each other at the surface and permit e-~ Al;..., of pressure into the ~..". .;uLl;..e line 76 while ~ _--Liug back flow at the end of the high pressure gas injection. Because the ,u~uJu~,Lu~ tubing 40 and the annulus 38 are fluidly connected to eo ~ g line 76, they encounter the same back pressure and are equalized in pressure so the fluid can reach a static10 e l l;l" ;~ ... in the pluJu~Lùu tubing 40 and the annulus 38. During the injection of high pressure gas 18 down the high pressure tubing 46 and the ejection of fluids up the lu~uJu~,~iu~ tubing 40 through the injection line 74 and into the u~ c. line 76, the check valve 29 permits the fluid flow to the collector 20 and prevents fluid flow to the annulus 38. The check valve 82 15 fluidly separates the inductor 14 from the annulus 38 to allow the inductor 14 to reduce the pressure on the ~-uJu Lun tubing 40 to a pressure below that of the K line 76 and thus the annulus 38.
There are many possible variations to the above ground plumbing g.r ~ I shown in F~G. 1. Some of the all_.~t;._ ~ l-o~ of the 20 plumbing A- ~ are illustrated in FIGS S and 6. It is important to 1 that the induction unit 14 and the above ground plumbing can be ~ _v~L~;uu~,d so as to eliminate or add various , as long as the induction unit 14 decreases the pressure in the ~-ulu~,Lul- tubing with respect to the head pressure, effectively increasing the pressure di~ ,..L~I or pressure 25 gradient within the ,u~uJu Lu~ tubing so that the head pressure forces water into the ~uJu~,Lu~ tubing to increase the volume of water lifted by the artificial lift system.
There are several pressure ll~ lulcilll .Ib relevant to ~ e the head pressure in the artificial lift system and the impact of the induction 30 unit 14 on bore hole 26 e ~ .. and therefore the induced fluid level 34 within the production tubing 40. It is possible to place a pressure l~Ju~,. at the bottom of the production tubing 40, but it is generally not practical. The head pressure can be calculated from either the pressure in the annulus or the WO 96/06263 r~ X,,3/1 -' -12- 219~()3~

~-udu~Lion tubing because the pressure in the annulus and the production tubing at the bottom of the well are equal to the head pressure if they both terminate at the same location within the bore hole. The pressure im the annulus and the production tubing at the point of t~ - l; - in the bottom of the well is equal S to the sum of the back pressure, the hydrostatic pressure of the gas, and the L~d.u~L~Lc pressure of the water in the amlulus and the ~IUVu~liUU tubing, The LJ~Lu~Lc pressures in the annulus and the ~u~udu~;Lù~ tubing 40 are commonly measured in the terms of pressure gradients. "Gradient" is 10 defined as Ibs. per square inch (psi) per vertical foot in the bore hole. Forexample, fresh water will have gradient of .433 psi per vertical foot whereas anuu~ci~uli~d gas gradient may be as low as .002 psi per vertical foot In effect, a 1000 foot column of fresh water will have a bottom hole or head pressure of 433 psi whereas 1000 feet of uu~ u-i~d gas would have a bottorn hole or head pressure of 2 psi. Acoustic methods are used to determine the depth in the annulus or ,u-udu- Lun tubing of the gas/water interface. This LU.,U.~UU~
is compared to the known depth of the annulus or ~u~uJu_ iull tubing to calculate the length of the gas and fluid columns, which are multiplied by the gradient to determine the l.,d.u~L. pressure of the gas and water.
The back pressure is added to the surn of the L~.Lu~aLc pressure to obtain a value for the head pressure. The back pressure is created because most artificial lift systems discharge fluids or gas into a u.~ p.vdu. Luu line, such as pludu~Lul. Iine 2S, and pipeline system that directs the fluids or gas to a collector, such as collector 20, at the ~udu~ Luu facility. This gathering system pressure promotes flow from the well head to the production facility, it also aids in the discharge of the fluid from the collector 20 to a tanlc, and the gas to a cuu.~ ,., because most WIU~IC~VI~ except in rare cullri6~uaLuL~, require a positive inlet pressure to perform efflciently. A portion of back pressure is ~ lr to the friction of moving the fluid from the well 30 assembly through the production hne 2S to the coLector, which can be several miles.
To increase the volume of water iII the ~JIUI.hl~,liUU tubing 40, the induction system 14 is activated to reduce the pressure at the upper end of the .. _ .. . .. . _ .

WO g6106:~63 PCT/US95/100~6 -13- ~ I ~J~)30 .~
uJu~,~iù-- tubing, which causes the fluid in the lJlUdU.l.lUll tubing to lose static c l .;l;l,.; ., As the induction system 14 is activated, the low pressure extends into the luluJu.~iull tubing 40, relieves the back pressure from the ,UlUJU~IiUll tubing and removes the gas from the upper end of the UlUdU~LiUII tubing. The S loss of the back pressure and h~u~Lc pressure associated with the gas in h~ with the continued pressure reduction by the induction system increases the pressure differential between the upper end of the yludu~Lùll tubing and the lower end of the l,ludu.Lùu tubing. In response to the loss of e~llilihTillm induced by the low pressure area, water is drawn from the 10 formation into the pludu~Lull tubing in an attempt by the system to reach a new static c l.. l;l"; -, The new static ~ ;l.. ;.. is achieved when the h~Jlu~ic head pressure associated with the volume of fluid drawn into the pll l~
tubing is equal to the'net pressure decrease associated with the induction system. For example, assume the induction system can reduce the pressure at 15 the top of the ~lu-lu~Lull tubing 20 psig, then a volume of fluid with a hydrostatic pressure of 20 psig will be drawn into the ~luJu~Lu-- tubing, all other things being equaL
In the plumbing ~'"'r;6~ " illustrated in FIG. 1 in which the ,u~uJu~Lu~ tubing and the annulus both have the same back pressure, the 20 increased fluid level in the p-udu-Lul- tubing can be described and calculated as the difference or change in pressure between the annulus and the lu~udu~Luu tubing. However, it should be noted that such a, , is only relevant when the ~.~ ' tubing and annulus have the same back pressure and head pressure. After the induction system is run for a time, the artificial lift system 25 obtains a steady state and the system reaches a new static e~ 1;1--; ... The head pressure of the formation, which is measured by the sum of the pressures in the annulus, will raise an induced column of fluid 34 in the ~l. ' tubing 40 until the sum of the surface pressures in the pl~ h tubing 40, and the pressure gradients in the plUdll.,iiU~I tubing 40, are equal to the sum of the 30 pressures in the IJlUdU~IiUII line 25, measured by the surface back pressure and the pressure gradients in the annulus 38. In other words, because the armulus 38 and the IllUdU~,LiUII tubing 40 initially have the same back pressure, the hydrostatic pressure of the volurne of fluid drawn into the ~uluJu~Lùll tubing is 21 q~O30 equal to the net change between the back pressure of the annulus and the surface pressure in the ,u~uJu-;liun tubing. This induced fluid level is expressed in the formula:
(((APTGP - AAGP) ~ TD) + SDP) / FG = IFL
5 Where APTGP is average ~.~ ' tubing 40 gradient pressure, AAGP is average armulus 38 gradient pressure to bottom of ,uludh~.Liu~ tubing 40, TD is depth in feet to the bottom of the ,uludh~Liuu tubing 40, SDP is surface pressure differential in psi between the ~lodh~iiuu tubing 40 and the annulus 38, FG is the gradient pressure of the fluid 32 in the bore hole 26, and IFL is the induced 10 fluid level 34 in feet above the static fluid level 33 in the formation 28.
Referring to FIGS. 1 and 2, the induction system 14 comprises a pressure reducer or inductor 90 tbat is fluidly connected to the 1,l~ ' tubing 40 via the lubricator 66 and creates a low pressure area in the luluJu~,i~u tubing 40 to raise the induced level of water 34 in the ,uludù~Liull tubing 40 15 above the level of the static fluid level 33 in the formation 28. The fluid level 33 in the formation and annulus is referred to as the static level. The level ofwater in the annulus 38 is the same as tbe static level of water 33 in the formation 28 because the formation 28 and the annulus 38 are fluidly connected by the p r~ 23 or the open end of the casing. As illllctr~t~ri. the 20 inductor 90 works on the venturi principle. However, it should be noted that other suitable devices capable of d~ lu,uhlg a reduced or low pressure in the production tubing can also be used within the scope of the invention.
The inductor 90 is also fluidly connected to the high pressure gas source 18 by a high pressure gas line 92 and to the injection line 74. A
25 regulator 93 is disposed in the high pressure gas line 92 to control pressure on the induction nozzle and a valve 94 is disposed in the high pressure gas line 92to shut off the high pressure gas 18 flow if desired.
The inductor 90 comprises a main body 96 that is generally tubular in cross section and which has a first an upper end 98 and a second 30 lower end 100. An axial bore 102 extends through the main body 96 from the first end 98 to the second end 100. The first end 98 is adapted to receive gas from the high pressure gas source 18 through a nozzle retainer inlet 136. The second end 100 is adapted to be connected to the ~ iug line 76 SO that ,,, . , _ _ _ _ _ .

W096106263 15 2 ~ )30 the high pressure gas entering tne main body 96 through the first end 98 will exit the second end 100 into the c~ line 76. Alt~.~uali~ the second end 100 could be comnected to the IJ-udu- Iiuu line 25, injection line 74 or anyotber a~lu~lial~ location d~ .Ic7il~ auu of check valve 82. As stated before, 5 various plumbing i~",-uL . ,- t~ may be used including the a~ of the inductor 90 low pressure inlet to the injection line 74 outlet and the inductor 90 discharge into the ~- ~cl;~C hne 76 inlet. In effect this would place the inductor 90 in series with the plumbing rather than in paralleL
A transverse bore 104 is disposed in the side of the main body 96 10 and is preferably oriented p_.~ 1 Iy with respect to the axially bore 102.
Preferably, the transverse bore 104 has thrcads 103 for receiving the threaded end of an induction line lOS that extends from the lubricator 66 to the inductor90 to fluidly connect the inductor 90 to the lubricator 66 and ~ludu. liull tubing 40. All~lu~.Li._ly, the transverse bore 104 could be comnected to the injection 15 line 74.
According to the ill ~~- the induction line 105 has a valve 107 and a check valve 109 dis,oosed in-line between the IlluJ~Liuu tubing 40 and the inductor 14, however, these are optional c~ that allow for ease of isolation but do not impact the p~ r.... - ~ of the inductor 14. The ~alve 107 is manually activated and opens and closes the induction line 10S. The check valve 109 is a one-way valve that prohibits the back flow of fluid from the inductor to the ~ludu- liun tubing 40.
The inductor 90 further comprises a nozzle 110 and an induction barrel 112 mounted within the axial bore 102 of the main body 96. Preferably the nozle 110 and the induction barrel 112 are held within the axial bore 102 by nozzle retainer 114 and barrel retainer 116. The noz21e retainer 114 is adapted to receive and mount the high pressure line 92. Likewise, the barrel retainer 116 is adapted to receive and mount the injection line 74, line 76 or the ~ludu~Liùu line 2S.
The nozle 110 has an annular shoulder 120 from which extends a conical portion 1~. An axially oriented aperture 124 extends from the annular shoulder 120 to a terminal end 126 of the conical portion 1~. The aperture 124 decreases in diameter as it ~ JIU~h~S the terrninal end 126 to define a ~;UIIt~ Slllg profile.
The nozzle retainer 114 is ~hlcdddl,:.~ mounted to the main body 96 to secure the nozzle retainer 114 to the main body 96. The threaded S conn~ n between the nozle retainer and main body provides ease of access for assembly, inspection and .~ One or more O-rings 132 are disposed about the ch~ Icu~e of the lower end of the nozle retainer 114 to form a fluid seal between the nozzle retainer 114 and the rnain body 96.
To secure the nozzle 110 within the main body 96, the annular 10 shoulder 120 of the nozzle 110 is abutted against an annular shoulder 134 extending into the axial bore 102 of the main body 96. The nozle retainer 114 is then positioned m the first end 98 of the rnain body 96. As the nozzle retainer 114 is tightened, the O-rings 132 form a seal agamst the sides of the axial bore 102. The nozzle retainer 114 is tightened until the end of the nozle 15 retainer 114 abuts the annular shoulder 120 of the nozzle 110 to ~,ulu~-c..
hold the nozzle 110 between the nozzle retainer 114 and the shoulder 134.
The induction barrel 114 comprises a body 138 havmg an annular shoulder 140. An aperture 142 extends axially through the body 138 and amlular shoulder 140. The aperture preferably comprises a ~,u...~ g inlet 144 20 conmected to a diverging outlet 146 by a sllhct~nt~ y constant diameter portion 148.
The barrel retainer 116 comprises a body 150 having an axially extending aperture or barrel retainer outlet 152. An almular shoulder 154 extends into the barrel retainer outlet 152. A portion of the body 150 has 25 threads 156 for engaging the threads 108 of the main body 96. One or more O-rings 158 are placed about the ~ u-..E~ ,n~c of the end of the body 150.
To mount the induction barrel 112 within the main body 96 of the inductor 90, the induction barrel 112 is disposed within the axial bore 102 of the main body 96 until the shoulder 140 of the induction barrel 112 abuts an 30 annular shoulder 162 of the main bûdy 96. The barrel retainer 116 is then positioned into the main body. As the barrel retamer 116 enters into the rnain body 96, the O-rings 158 form a seal between the barrel retainer 116 and the main body 96. The barrel retainer 116 is threaded until the almular shoulder .

~l9~o wos6l06263 2 ~ q~U ~IUS95/l0056 ~.
140 of the barrel is co .y~ Od between the annular shoulder 162 of the main body and the end of the barrel retainer 116.
Spacers 166 can be disposed between the annular shoulder 120 of the nozzle 110 and the shoulder 134 of the body 96 to adjust the position of theS nozzle 110. Although spacers 166 generally provide enough -~; between the nozzle 110 and the induction barrel 112, spacers 168 can be disposed between the shoulder 162 of the body 96 and the armular shoulder 140 of the induction barrel 112 to adjust the position of the induction barrel 138. By adjusting the position of the noz21e 110 and induction barrel 138 with different10 thickness or multiple spacers 166 and 168, ~ e~ L~ , the position of the nozzle 110 vvith respect to the induction barrel 138 can be adjusted to control the flow of fluid exiting the induction line 105 and entering the induction barrel 138. In most ~ , the spacing between the nozzle 110 and the induction barrel 138 can be very critical, especially because the speed of the gas exiting15 the terminal end 126 of the nozle 110 can achieve ~u~. - velocities.
Referring to FIGS. 1 and 2, prior to initiation of the artificial lift system 10, the fluid in the 1~ tubing 40 and the formation 28 is in staticc-l. ;I;l..; .. Because the system is in static c~l ;l;h.; .. httle or no fluid in the form of natural gas can escape from the formation 28 into the armulus 38. To promote the escape of natural gas from the formation 28 and into the annulus 38, it is necessary to remove the water from the formation, which reduces the head pressure of the formation 28. By removing the water, the gas in the formation has a greater volume in which to expand and move, enabling trapped gas to migrate toward the well.
Prior to activating the artificial lift system 10, the valves 27, 58, 70, 80, 94, and 107 are all moved to the open position. The annulus 38 pressure gradient, the p,udu.Lu-l tubing 40 pressure gradient and surface pressures equalize via the injection line 74, the '~ L line 76 and the ~Jludu, Lu hne 25, having the effect of equalizing the static fluid levels in the annulus 38 30 and ~ludu~Luu tubing 40. Depending on the amount of back pressure in the annulus and ~uludu~,Lull tubing, the static fluid levels in the annulus and production tubing may or may not coincide with the static fluid level of the formatiûn until the system is equalized. Also, if, for some reason, the back W 096/06263 PC~rrUS95/10056 -18- 21 9~03~

pressure in the annulus is the different from the back pressure in the y~udu-,iun tubing, the static fluid levels in the annulus and the prùdu~Liuu tubing may or may not coincide when the production tubing and annulus are equalized into their respective l~ludu~ lioll lines. It is not necessary in practicing the invention S for the static fluid levels in the formation, annulus or ~ludu~ Liun tubing to coincide.
When the valves 27,70,80,94 and 107 are opened, the high pressure gas is directed into the induction system 14 to begin reducing the production tubing 40 surface pressure. As the high pressure gas flows into the 10 inductor, it passes through the no_zle inlet 136 of the no zle retainer 114 until it the cu~ ~u6 aperture 124 of the no~le 110. As the high pressure gas is directed from the terminal end 126 of the _.6i.l~ aperture of the no771e 110, the gas is ~ .,- . d and directed into the ~u..~ g inlet 144 of the induction barrel 138. The high pressure gas is then directed through the 15 induction barrel where the velocity is slowed by expansion in the constant diameter portion 148 of the induction barrel 138 and exiting through the outlet aperture 152 into the collector 20 via the injection line 74, the ~ li..p Iine 76 or the lJ-udu~ Liun line 25.
The ii~ 1 "t-~d high pressure gas exiting the no~le 110 results in the formation of a low pressure area within the axial bore 102 of the main body 96 adjacent the transverse opening 104, which creates a reduced pressure area in the inductiûn line 105 and ~ b~ .Y the pludu~liuu tubing 40. Upon the continued operation of the induction system, the gas in the plu.lu~Liun tubing is drawn off by the low pressure and carried through the induction line 105 and out to the collector 20 with the high pressure gas from the high pressure gas source 18. The low pressure or reduced pressure area reduces the ~IC ' tubing pressure gradient and upsets the static e-l, ;l;l..; ..-- of the system. In essence, an increased pressure diL~ d~l is created between pressure at the upper end of the production tubing and the head pressure at the lower end of the production tubing.
As the total pressure in the production tubing 40 decreases, water 32 is drawn into the ulu~lh-,Liull tubing 40 in an attempt by the system to obtain a new static c~ l,. I .. for the new ct)n~l;tir~nc As the high pressure gas . .
.. . . . .... . _ . . . .. _ _ . _ _ WO 96106263 PCr/US95/1aa56 -19- 2 1 9~030 continues to flow through the inductor 90, the pressure in the length of production tubing 40 above the liquid level will decrease. The fluid system attempts to reach a static eq~ ihrill7n by drawing or forcing fluid into the production tubing to ~ u ~ for the net pressure loss at the upper end of S the l~.odu~liuu tubing. A new static eqllil;hril~m is reached when the hJLva~Lic pressure of the volume of fluid drawn into the ~., ' tubing equals the decrease in pressure created by the induction system.
In the fluid system illustrated in FIG. 1, the increased volume of fluid is equal to the column of fluid standing in the ~.udu~liù.. tubing above the 10 static fluid level of the ~.u.lu.,~iuu tubing prior to the actuation of the induction system. In other plumbing ~ ~ ~f;c~ , it is possible the raised fluid column will not extend above the static fluid level because of a sllhct~nti~lly high back pressure.
After the high pressure gas is passed through the inductor for the 15 time necessary to acnieve maximum di~ ..Lal plus a period of time to ensure t'ae maximum amount of water is lifted and to ensure that the well bore will notdewater and dry ycle, the controller 60 opens the motor valve 56 for a t~ d period of time, and nigh pressure gas from the high pressure gas source 18 passes down the high pressure tubing 46 where it is injected into the 20 ~-udu. ~iu-- tubing 40 th-rough t'ne injection mandrel 42. Alt~.llali71~7 a pressure sensor 170 can be positioned on the tubing or t'ne annulus and when the pressure in the tubing or armulus reaches a 1~ d.; ~ ' leveL the high pressure gas will be injected into the ~.~ ' tubing 40 for a ~-~,d ~' time period. As the high pressure gas enters the ~, h tubing, the standing 25 valve 44 is closed by the increased pressure from th-e high pressure gas and the plunger 48 is driven upwardly within the ~.u-lu. Lu.. tubing 40 by the blast of auli~.,d gas, lifting the raised column of fluid above the plunger toward the surface 24 and the lubricator 66. The rising column of fluid is directed into the injection !ine 74, through the ~ J; ~ line 76 and finally into the 30 production line 25 and eventually to the collector 20. Tne advance of the plunger 48 is slowed by the CUll~yl~aaiUll of the water as the water and plungerreach the top of the lubricator 66. The plunger 48 contacts the spring 68 and isdirected back toward the injection mandrel 42. Some of the water lifted by the -20- 21 9~030 plunger 48 will enter the induction line 105 and pass through the inductor 90 onits way to the collector 20 via the ,ulud~ iou line 25.
Upon the removal of the column of fluid from the formation, the system is not equalized and fluid, such as natural gas, will be released from the 5 formation and migrate toward the well bore. Some of the natural gas will enterthe annulus 38 through the E)~ r~ 23 or open bore hole section and will move upwardly in the annulus 38 because of the head pressure and the density differential between the natural gas and tbe water in the formation, and pass through the ,uludul.Liull line 25 to the collector 20. The combined fluid of water 10 . nd gas entering the collector 20 is then separated into the natural gas andwater ~ The natural gas is then stored or shipped to the a~ U~lial~
facility. The process is repeated until the water is cllbctqntiqlly removed fromthe formation.
FIGS. 1 and 2 illustrate the preferred ~ .I-o-~ of the artificial 15 lift system 10 according to the invention. However, there are rnany variations and ~.. . h;. _l;.",~ of bore hole, Ul,liUn and plumbing ~ ;6~ in which the induction system 14 can be iUWl,UUl~.d. FIGS. 3 and 4 illustrate Iternative l-ù-l; -- ~ for the bore hole Cfl~ , and FIGS. 5 and 6 illustrate alternative ....I..,.I;..,...I~ for the plumbing . o..l;~.,.,~;.. ~ Any 20 ~--. .h; .~ . of the bore ~u~h~-,Liun, plumbing CU~ laiiUll and induction system 14 is possible. The alternative ~ -l.o.l;~ of FIGS. 3-6 have several of the same parts illustrated in ~IGS. 1 and 2. Therefore, like numerals are used to identify like parts.
FIG. 3 5~ illustrates a second ~ 3,o-l;~ l of the bore 25 hole ~ u~ll h~.~iUII for a well assembly having a rat hole. The well assembly 200 is cllhctqntiqlly similar to the well assembly illustrated in FIG. 1, except that formation 28 has a bottom 202 and a portion 204 of the bore hole 26 extends below the bottom of the formation 28. The portion 204 of the bore hole 26, which extends beyond the bottom of the formation, is referred to as a "rat hole."
30 The rat hole 204 generally extends between 10 and 500 feet below the bottom of the formation. However, the length of the rat hûle varies from well to well.
The casing 22 has a portion 206 that extends into the rat hole 204. Similarly, the production tubing 40 has â portion 208 that extends ~ y into the rat .. . , . . . . . . . . . . . _ . _ . . _ ..

WO 96106263 PCT~DS95~10056 -21- 2 ~ 3 0 .
hole. The injection mandrel 42 is positioned at the bottom of ~JIWIU~liUU tubing40 so that tbe greatest column of fluid can be raised by the artificial lift system.
Likewise, the high pressure tubing 46 extend to the bottom of the ,uludu~Liu tubing and into the injection mandrel 42.
FIG. 4 illu trates a third c I,o~ of the bore hole cu~lu~iun for a well assembly 220 with a rat hole 204. The well assembly 220 is cllhct~ lly identical to the well as embly 200, except that the injection mandrel 42 is not positioned adjacent the bottom of the plUJU~I.iUll tubing, butis disposed a ,u-~J~ t- ..,;~.~d di tance above the bottom of the plUllU~LiUU tubing 10 40 and preferably below the bottom of the formation. The injection mandrel 42i positioned above the bottom of the ~JIUdU~IiUll tubing 40 so that wben a standing valve 44 is not present in the UIUJU~I.iU~ tubing 40 the high pressure gas 18 injected into the injection mandrel 42 will exit up the p. . ' tubing 40, forcing a column of water out of tbe top plUdU.,LiUII tubing 40 because this15 ~ ..1. ' the path of least resi tance. The location of the mandrel 42 is dictated by the . .~ c staff of each particular company to - - -mc ' their individual ,ulvdu~liùll,ulef~
FIG. 5 illu trates a second e ~I-ù-I; l of the plumbing r~G.~ ,~;~ ~ which i s ~ I ,I; IIy identical to the plumbing . ~ of 20 FIG. 1, except that the ejected water and ,u. u~ gas are not ~ d and carried to the collector 20 along a common line. Also, while the collector is indicated as a single unit it needs to be ....~i. o. od that multiple collectors are possible in which the fluids and gas exiting the injection line 302 and the ~UIVdU~LiOU Iine 304 may terminate at different collectors.
The second plumbing ~.. r~ ;... 300 comprises separated injection line 302 and UlVdU-LiUII line 304. The injection line 302 is fluidly connected to the lubricator 66 and extends to a collector 20 for separating and collecting the liquid and gas passing through the injection line 302. The injection line 302 has a valve 306 and a check valve 308, which prohibits the 30 back flow of fluid from the injection line 302 into the lubricator 66.
The ,UIUdU~.LiOII line 304 i fluidly connected to the casing 22 at the well head and extends to the collector 20 where the gas i collected for shipment. The ~ludu-liùLt line 304 also comprises a valve 310 and a .

W096/06263 P~T~US95110056 21 ~03Q
check valve 312, which prohibits the back flow of gas into the annuius of the casing 22.
The second plumbing ~ U...~ic.... l ;...l 300 also illustrates an optional inct~ otinn of a ~u,~,u~ 314. The .u...~ u- is fluidly connected to the ,u~udu. Liou line 304 by ~;UI--U-~.. UI line 316. Valves 318 and 320 are placed in the CUIU,U~G...~U- Iine on opposite sides of the ~;UIII,U-C....(JI and between the ~uduuLiu~ line and a third valve 322 is positioned in the production line between the c~ points for the cu~c~u~ line so that the gas flowing through the ,u.u.lu~Lio.. Iine can be routed through the ~UU~ ..Jr or around 10 the CUI~ depending on the particular need. The co,u~c~u~ 314 essentially functions as a pump and aids in moving the gas from the well head 36 to the collector 20. The CU~ -C~.~OI can also be added to the plumbing ~;w-r~u-~LLiul~ of Fig. 1.
Although the distance between the well head 36 and the collector 15 20 appears to be relatively small as s~ lly illllCtrZltf'.-l, the real distance can be several miles. The length of the vludu~Liul~ line induces frictional forces in the flow of the gas from the well head to the collector, resulting in a back pressure forming in the production line. The CUlU~U~ .U- aids tbe flow of the fluid against the back pressure. Typically, the back pressure and the ~,.udu.liuu 20 line can range from 2û to 80 psig.
The rest of the second plumbing c.- r~ 300 is identical to the plumbing ,....r;," .,.l;..,~ illustrated in FIG. 1, including the induction line 105 and induction system 14. The back pressure in the injection line can vary between 50 and 100 psig.
The operation of the second plumbing c.. rir~ ;-- 300 is similar to the operation of the first plumbing ~ - ri~". .I;~..~ The main physical difference in the first plumbing c....ri~"..,.,;.~.. and the second plumbing ~u~r~ u ;~ ~.. is that, unlike the first plumbing ~u~rc.~ the back pressures associated with the injection line 302 and production line 304 are no longer 30 equal because the injection line 302 and ~ùdu~Liu~ line 304 are physically separated. Therefore, the static fluid level in the annulus is not ne~ uily equal to the static fluid level in the ~,.udu~Liuu tubing. It is quite possible that .
, _ . .

~ -23- 2 ~ 9~U30 the level of fluid m the production tubing will be below the fluid level in the annulus and the static fluid level in the formation.
Prior to the initiation of the induction system 14, the fluid system is in static ~ il..; " - and the total pressure at the ~ iu~. point of the 5 production tubing 40 is equal to the sum of the back pressure in the injectionline, the L~Lu~h~ic pressure of the gas m the ,u-udu~uuu tubing 40, and the L~llu~l~Lc pressure of the water in the ~lu~ Lwl tubing 40. Similarly, the total pressure in tbe annulus at the pomt of the ~IUdU~LUII tubing is equal to the sum of the back pressure m thc production line, the LJI.U~hL~
10 pressure of the gas m the almulus, and the hJI~u~hLc pressure of the water inthe almulus. The total pressure in the ,U-UUU~LUU tubing and the a~mulus at the injection mandrel are both equal to the head pressure of the forrnation at the injection mandreL
Prior to the activation of the induction system 14, the valves 58, 15 70, 94, 107, 306, 310, and 3~ are opened. As the induction system 14 is activated, the pressure is reduced at the upper end of the ~.U.IU.LU.. tubimg 40to create a low pressure area near the induction unit 14, which relieves the back pressure and draws the gas from the UIUU~._LUU tubing 40 through the induction unit and into the injection line 302 where it is directed towards a collector 20.
20 Ultimately, the continued operation of the induction unit will reduce the pressure in the 1" ~"l .. I ;. . tubmg to the point where it is equal to the lowpressure created by the induction unit 14. As the pressure is being reducedL thefluid attempts to stay in ~ l .;1;1"; .. so that the total pressure in the ~ulu-lul Lo~
tubing equals the head pressure of the formation at the injection m~mdrel. To stay in ~ ";,, the reduction m the pressure by the induction unit at the upper end of the production tubing 40 is offset by an increase in the fluid volume in the production tubing 40. The imcrease m the volume of fluid in the PIUIU~LUII tubing 40 will have a hJllv~hLc pressure equal to that amount of pressure reduced in the upper end of the l~UIU~Loll tubing.
After the induction unit 14 is run long enough to establish a steady state condition, or, m other words, a new e ~ the controller 60 initiates the injection of high pressure gas from the high pressure gas source 18, through the high pressure tubing 46 and into the injection mandrel 42 to lift the W096106263 a 19~030 PCT~US95110056 -24- 2 ~ q80~

plunger 48 and the column of fluid above the plunger 48 upwardly toward the surface of the well. Preferably, as the column of fluid is lifted, the controller 60 begins turning off the high pressure gas directed to the induction unit 14.
However, it is not necessary for the induction unit to be turned off during the 5 lifting of the water. The lifted water is then directed into the injection line 302 where it passes through the valve 306 and the check valve 308 and is carried to the collector 20. The water lifted by the plunger is under pressure from the high pressure gas used to lift the column of fluid and the friction associated with moving the fluid through the injection line to the collector. The pressure 10 associated with the moving fluid is a factor in ~1~ t~ the back pressure in the injection line 302.
As the water is removed from the formation, the volume of liquid in the formation is reduced. The volume of fluid removed by the artificial lift ystem is replaced by an equal volume of gas trapped in the formation. The gas 15 is then free to migrate into the casing through the 1) r.~ in the casing,where it moves through the annulus, through the UlUUU~UUIl line and to the collector 20. If the head pressure of the formation is not great enough to obtain the desired flow of gas out of the formation, such as in the case of a relatively high back pressure, the ~;I,JIII~UI~ UI 316 can be actuated to pump the gas from20 the annulus and force it to the collector 20. The ~;u...~ u. is generally rununtil the pressure in the ~u~ùdu~,liu~ line 304 reaches a ~ d value where it is no longer practical to run the cu~ul~ ol to extract further gas.
It should be evident that the induction system 14 is particularly efficient when the system for whatever reason has a large back pressure, which 25 many closed systems do. The back pressure prevents the flow of fluid, such aswater from the formation into thç ~udu~,~iu~ tubing. As the induction ystem relieves the back pressure, there is a ~u~ u~di~; increase in the volume of fluid in the production tubing. AJ~ 'y, the induction system can further increase the volume of fluid by reducing the hydrostatic pressure of the gas in 30 the production tubing. Last, the induction system can create a low pressure area or a relative, local negative pressure area to further increase the volume of fluid in the production tubing 40. The greater the volume of fluid in the Wo 96~06~63 PCT/US95/lOOS6 ~ -25-2 1 '3~030 ~)IUdU~;LiUII tubing, the greater is the ~ of the artificial lift system indewatering the well and the production of gas.
FIG. 6 illustrates a third l,o~ of the plumbing cu~,ulaLiOIl 400, which is similar to both the first and second plumbing S ~u~l~ula~u~. Unlike the second plumbing c(ll~r~c~ 300, the third plumbing ~--.-r~ .O~;-... 400 has a separator located near the well assembly.
Parts of the third plumbing ,.. rL .. ,.. 400 that are like parts in the first and second plumbing ~ are identified by like numerals.
The third plumbing .-~ includes a separate injection hne 10 302 and ~-udu~L;uu line 304 as illustrated in FIG. S for the second plumbing ~- r~ However, the injection line 302 flows to a separator 402 that is positioned on location adjacent the well. The separator 402 separates the fluid and the gas entering through the injection line 302. A water line 404 extends from the separator and carries the water from the separator to a collector 20 at15 the storage facility.
A gas line 406 extends from the separator 402 to the ~
line 304 and carries the gas from the separator to the ~.l ' hne where the gas is then carried to the collector 20. A motor valve 408 is positioned in the gas line 406 between the separator 402 and the IJlUdU~,LiUU 304 and is set so that 20 it blocks the flow of gas from the separator 402 to the ~IUdU~,LiUU line 304 during the injection of high pressure gas to permit the separator to generate sufficient pressure to move the water from the separator 402 dovvn the water line 404 to the collector 20. A back pressure valve 410 is positioned within a back pressure line 412 that bypasses the motor valve 408. The back pressure 25 valve permits the separator from U._-~JlC..~..lllLlUg during the injection cycle.
Although the induction unit 14 is illustrated as being mounted in the same manner as the first and second plumbing c-~ ~ , which is upstream of the separator, it is possible to mount the induction unit du..~ o~u of the separator on either the water line 404 or the gas line 406. The 30 du..l~llcaul mounting may be preferable to limit the flow of water through the induction system 14.
An optional motor valve 412 may be positioned between the check valve 312 and the collector 20, preferably in front of the cu~ lc~l linc 316 W 096/06263 a iq8~30 PC~rrOS95/lOOS6 -26- 21 ~03~

and may be opened and closed at the d~lu~JliaLc times to enbance well bore fluid dynamics.
The operation of tbe third plumbing c~ - r;g, , l ;~ .. . is initially similar to the operation of tbe first plumbing ~ of FIG. 1 in that S prior to tbe closing of the motor valve 408, the injection line 302 is fluidlyconnected to the ~-uJu~Liu-- Iine 304 by the gas line 406. In this state, the system operates cllhct~nti~lly like the first plumbing ~ r;f,,..~l;,.,. in that the back pressure in the injection line 302 and the ,u-uducLiu-- line 304 are s~lbst~nti~11y equal. Upon the activation of the induction system, tbe back 10 pressure in the ~l uJu~ Liu~l tubing is reduced, the gas is drawn from the ~luJu~Liu-l tubing, and the pressure at the upper end of the ~luJu~;Liuu tubing is reduced as previously described and fluid is drawn into the production tubing.
After a ~Ir1ft ...; d amount of time passes, the controller 60 closes the motor valves 408 and optional motor valve 412 and injects the high lS pressure gas into the ~IIUJU~ iU~I tubing 40 to raise the fluid in the I~luJu~Liuu tubing to the surface of the well. The closing of motor valve 408 permits the build up of pressure in the separator 402.
The controller 60 may or may not shut off the high pressure gas passing through the induction system. However, it may be preferred that the controller turn off the high pressure gas passing through the induction system 14 after the high pressure gas is injected into the IJlUdU-liUII tubing to conserve the quantity of gas used during each cycle.
The lifted gas and water and the high pressure gas is then directed through the injection line 302 and into the separator 402 where it is separated into its ~ 1 elements of gas and water. The closed motor valve 4t)8 permits the pressure in the separator to increase to a ,ulc~ . rd level so that the water can be discharged into ~luJu.liu-- line 404 and carried to the collector 20. If the pl~ - ....,. rd pressure is reached prior to the opening ofthe motor valve 408, the back pressure valve 410 opens to permit the gas to bypass the motor valve 408, to protect the separator 402 from over ~u-~ ~
and enter the l~-uJu~Liuu line 304 where the gas is then carried to the collector 20. When the water is moved from the separator, the controller 60 opens the WO 96106263 PCI~US95/10056 ~ -27-2~ ~8030 motor valve 408 to permit the flow of the remaining gas from the separator 402 to the ~ludu~ Liull hne 304 and to the collector 20.
As in the first and second plumbing ~ the third plumbing ~ 400 can use a ~ UI 314 to aid in moving the gas 5 through the production hne 304 to the collector 20. Also, the motor valve 412 is optional in the third cLulJod;lll_Lll.
To q~...... n.l~ the ~ ull~,Lu.LIb of the real world, the or ~o~ ;.... .. of valves, check valves and plumbing is modified from well to well and from company to company according to individual 10 production i ' , ar,d ~ f. .l n~. i,. However, the intent of the invention does not change in that it is to reduce the tubing pressure to increase the volume of fluid to be removed from the ,UlUdU-,LiUU tubing during the artificiallifting step and to offer a systematic and yl~ alJle method of control for a ~,..1.~ .- r~ e gas lift system.
The invention provides a dramatic increase in the effficiency and ~,.~.li. l, l ly of artificial lift systemc and processes, especially r gas liftsystems and processes. The invention greatly increases the effficiency of the . r- f gas lift system and method by enhancing the ability of the Cllhc-- f ~~
gas lift system and method to lift a greater amount of fluid from the formation 20 during each lifting cycle, resulting in a dramatic increase in the ~UI~ ' " of natural gas from the fnnr~qtinn Further, the invention also enables the sllhcllrfPre gas lift system to remove ~ all of the water from the formation and, thus, ~"l,~l~..l;_lly all the natural gas, whereas previous 5llhcllrfq~ ~ gas lift systems could not e 1'~ remove all of the water from 25 the fnnnqtinn requiring the in~t~llqtin~ of the less desirable beam pump to complete the d~v~tprin~ process or leaving ulu~LIi_vdl~lc natural gas in the fnnnqtinn The inability of previous 5~hc~rfq~e gas lift systems to extract all the water from the well . ~ ~ c, d the use of the more expensive and less el.v;lu,.ll,_L~ friendly artificial lift systems, such as beam pumps, which 30 increased the cost of gas ,u~udu~;LiuL~. Also, if the pressure sensing control system is used with the inductor and cycle timing becomes a function of bore hole conditions rather than arbitrary cycle times, a cllhct~nti~l reduction in the recycle gas and CU~ ,aai~)ll b-rs, _ .. I necessary tû operate the SSGL will be WO 96/06~63 PCT/US95110056 realized. Therefore, the invention increases the efficiency and ~ludu~.l.ilJll of natural gas, while c; . ~ ly reducing the cost of producing the natural gas and increasing the Cll~llUlllU~ and o~ 1 safety by offering a systernatic method of control.
S While particular e ~ o~ of the invention have been shown, it will be ~ luod, of course, that the invention is not limited thereto since ."...llr;. 11-...~ may be made by those skilled in the art, particularly in light of the foregoing teachings. For example, although the fluid in the formation is described as natural gas and water, the fluid can also be liquid L~ù~bu~, 10 such as oiL alone or in ~,... l: ~li-- . with natural gas. 12e~c~ng~ variation and 1"~ are possible within the scope of the foregoing disclosure of the invention without departing from the spirit of the invention.

Claims

Claims The embodiments of the invention in which an exclusive property or privilege is claimed are defined as follows:

1. In a method of producing gas from a gas and liquid containing underground strata in which a well extends between the surface of the ground and the strata and the well has a production tubing extending from the surface of the ground into the strata and from which the liquid is removed from the well and the well has at least at an upper portion thereof a casing which defines with the production tubing an annulus through which gas from the lower portion of the strata passes and is collected at the surface of the ground, and the liquid is artificially lifted from a lower portion of the well to the surface of the ground through the production tubing to release the gas from the formation to the annulus, the improvement comprising the step of:
reducing the pressure in the production tubing at an upper portion thereof to thereby increase the volume of liquid in the production tubing for subsequent removal in the artificial lifting step.

2. The method of claim 1 wherein the pressure reducing step is carried out for a first time period to increase the volume of liquid in the production tubing prior to the lifting of the liquid to the surface of the ground and the artificial lifting step is carried out subsequent to the first time period to lift the liquid to the surface of the ground.

3. The method of claim 2 wherein the artificial lifting step comprises injecting a high pressure gas for a second time period into the lower portion of the production tubing to lift the liquid in the production tubing.

4. The method of claim 3 wherein the second time period begins prior to the completion of the first time period.

5. The method of claim 3 wherein the second time period begins after the completion of the first time period.

6. The method of claim 1 wherein the pressure reducing step comprises passing a high pressure gas through a reduced orifice fluidly connected to the production tubing to create a reduced pressure area adjacent the orifice and drawing a portion of the liquid from the strata into the production tubing to be artificially lifted to surface.

7. The method of claim 1 and further comprising the step of directing the liquid lifted from the production tubing and the gas exiting the outer casing to a common tubing and separating the gas and liquid.

8. The method of claim 1 wherein the gas production well is closed with respect to the atmosphere.

9. The method of claim 1 wherein the liquid lifted from the strata is petroleum.

10. The method of claim 1 wherein the liquid lifted from the strata is water.

11. The method of claim 1 and further comprising the providing of a controller for controlling the initiation of the artificial lifting step.

12. The method of claim 1 wherein the artificial lifting step comprises injecting a high pressure gas into the lower portion of the productiontubing.

13. The method of claim 12 further comprising the separating of the high pressure gas and the liquid.

14. The method of claim 1 and further comprising the step of directing the liquid lifted from the production tubing to a first production line and the gas in the casing to a second production line, which is separated from the first production line.

15. In a method of producing gas from a gas and liquid containing underground strata in which a well extends between the surface of the ground and the strata and the well has a production tubing extending from the surface of the ground into the strata and from which the liquid is removed from the well and the well has at least at an upper portion thereof a casing which defines with the production tubing an annulus through which gas from the lower portion of the strata passes and is collected at the surface of the ground, and the liquid is artificially lifted from a lower portion of the well to the surface of the ground through the production tubing to release the gas from the formation to the annulus, the improvement comprising the step of:
increasing a pressure differential between the upper portion of the tubing and a lower portion of the production tubing in fluid contact with the liquid to thereby increase the volume of liquid in the production tubing for subsequent removal in the artificial lifting step.

16. In a gas production well wherein gas is produced from a gas and liquid containing underground strata in which a well extends between the surface of the ground and the strata and the well has a production tubing extending from the surface of the ground into the strata and from which the liquid is removed from the well and the well has at least at an upper portion thereof a casing which defines with the production tubing an annulus through which gas from the lower portion of the strata passes and is collected at the surface of the ground, and the liquid is artificially lifted by an artificial lift system from a lower portion of the well to the surface of the ground through theproduction tubing to release the gas from the formation to the annulus, the improvement comprising:
a pressure reducer fluidly connected to an upper portion of the production tubing to reduce the pressure at an upper portion of the production tubing to thereby increase the volume of liquid in the production tubing for subsequent removal of the artificial lifting system.

17. In a gas production well wherein gas is produced from a gas and liquid containing underground strata in which a well extends between the surface of the ground and the strata and the well has a production tubing extending from the surface of the ground into the strata and from which the liquid is removed from the well and the well has at least at an upper portion thereof a casing which defines with the production tubing an annulus through which gas from the lower portion of the strata passes and is collected at the surface of the ground, and the liquid is artificially lifted by an artificial lift system from a lower portion of the well to the surface of the ground through theproduction tubing to release the gas from the formation to the annulus, the a pressure reducer fluidly connected to an upper portion of the production tubing to create a pressure differential between the upper portion ofthe production tubing and an upper portion of the annulus to thereby increase the volume of liquid in the production tubing for subsequent removal of the artificial lifting system.

18. In a gas production well according to claims 16 or 17 wherein the pressure reducer is a venturi fluidly connected to a source of pressurized fluid so that when the pressurized fluid passes through the venturi a reduced pressure area is formed by the venturi, thereby increasing the volume ofliquid in the production tubing.

19. In a gas production well according to any of claims 16-18 wherein the venturi comprises a tubular body having an axial opening extending through the tubular body from a first end to a second end and in which is replaceably mounted a nozzle and an induction barrel.

20. In a gas production well according to any of claims 16-19 wherein the venturi further comprises a nozzle retainer threadably mounted to the axial aperture of the tubular body at the first end to retain the nozzle within the tubular body and a barrel retainer threadably mounted to the axial aperture of the tubular body at the second end to retain the induction barrel within the axial aperture of the tubular body, whereby the nozzle retainer and barrel retainer provide access to the nozzle and the induction barrel.

21. In a gas production well according to any of claims 16-20 wherein the tubular body has an annular shoulder extending into the axial aperture, the nozzle abuts one side of the annular shoulder and the nozzle retainer abuts the nozzle to compressively mount the nozzle within the tubular body.

22. In a gas production well according to any of claims 16-21 wherein spacers can be placed between the nozzle and the annular shoulder to adjust the position of the nozzle within the axial aperture.

23. In a gas production well according to any of claims 16-22 wherein the induction barrel abuts the another side of the annular shoulder and the barrel retainer abuts the induction barrel to compressively mount the induction barrel within the tubular body.

24. In a gas production well according to any of claims 16-23 wherein spacers can be placed between the induction barrel and the annular shoulder to adjust the position of the induction barrel within the axial aperture.

25. In a gas production well according to any of claims 16-24 and further comprising a production line extending from the casing for removal of the gas in the casing and the pressure reducer being fluidly connected to theproduction tubing.

26. In a gas production well according to any of claims 16-25 and further comprising an induction line extending from the production tubing to the pressure reducer for fluidly connecting the pressure reducer to the production tubing.